1. Field of the Invention
The present invention relates generally to methods and systems for production of hydrocarbons, hydrogen, and/or other products from various petroleum, kerogen, bitumen, oil shale, lignite and coal formations. Certain embodiments relate to in situ conversion of hydrocarbons and hydrocarbon-precursors (such as are found in coal, lignite and other carbon-containing geological formations) to produce hydrocarbons, hydrogen, and/or novel product streams from underground petroleum, oil shale and coal formations.
2. Description of Related Art
Carbon-rich deposits found in subterranean (e.g., sedimentary) formations are commonly used as energy resources, raw materials and chemical feedstocks. In recent years, concerns over depletion of available hydrocarbon resources and the declining quality of hydrocarbons produced by traditional methods have led to development of processes that allow for more efficient recovery, processing and/or use of geologically derived hydrocarbon resources. Work conducted over the last century established the possibility of producing liquid or gas hydrocarbons from mineralized and entrained sources. However, the work largely failed the test of practicality.
Conventional crude oil deposits normally contain oil, water, and gas as three separate phases that are produced by multiphase fluid flow. In such multiphase fluid flow, the volumetric content, as well as differences in adherence, surface area and interfacial surface tension of materials plays an important role in the recoverability of the various materials. For example, differences in interfacial surface tension between any two phases (and/or the materials within them) may interfere with the fluid flow of materials in one or more of these or other phases. This impedance may result in reduced relative permeability of the formation to at least one fluid phase. It may also reduce the effective permeability of the formation as a whole.
Likewise, interstitial forces acting upon the multi-phase formation fluids may impede mobility of such fluids in the formation. For example, interfacial tension between an oil droplet within the formation fluid and the mineral structure surrounding it acts to create a substantial capillary force that may act to retain the droplet in position. Acting across a formation, these localized interfacial behaviors may result in substantial non-recoverable, residual oil saturation left behind after the relative permeability to oil has been reduced to a low value. In addition, the differential viscosity and capillarity of each phase may cause interfingering (e.g. ‘channeling’) of flowing water and gas phases, thereby bypassing large segments of oil-saturated reservoir rock. This interfingering of flow is believed to account for a portion of the large residual, non-producible oil saturations remaining after depletion of most oil fields. Even after secondary and tertiary oil recovery technologies have been used, large volumes of oil, typically 35% to 70% of original oil-in-place, may remain in the depleted reservoir rock as non-recoverable oil.
In heavy oil and tar sand deposits, these differential viscosity and capillarity problems in multiphase flow may be even more significant, resulting in both very slow production rates and very high residual oil left behind after depletion. Steam injection is often used to heat the heavy oil or tar/bitumen to reduce oil viscosity, increase the oil production rate and decrease the bypassed residual, non-recoverable oil saturation. Chemical agents that reduce interfacial tension and capillary forces may further reduce the non-recoverable, residual oil left behind after depletion and abandonment. Even after such reduction of interfacial tension and decreased viscosity by steam heating, substantial volumes of this oil still remains non-recoverable at economic rates, based on such multiphase fluid flow.
Methods that reduce interfacial tensions, and the impedance of flow that may result from it, are highly desirable in the field of terrestrial hydrocarbon recovery and production. In situ methods for consolidating formation hydrocarbons into a single fluid phase are of immense interest in the field of fuel and chemical production. It is also highly desirable to employ in situ methods that allow for production of formation hydrocarbons having a substantially narrower, and/or more defined, and/or more controlled range of compositions than is found using conventional petroleum and natural gas production technologies. Generally, methods that would allow an operator increased control over the physical chemistry (phase behavior) of formation fluids would be of great value. Similarly, methods that provide an operator with increased control of the chemical composition of formation fluids would be of great value, especially in producing energy and chemical products. Methods that could allow an operator to gain control of the physical chemistry of formation fluids may also provide that operator to also gain a degree of compositional control over the chemistry of the fluids being produced from the formation. Conversely, gaining control of the compositional chemistry operating within the formation fluids, may provide an operator with increased control of the yield, physical chemistry and flow properties of the formation fluids.
The subject of this invention is the mobilization, transformation and recovery to advantage in an advantageous form of carbon-based materials from various geological formations. While the focus of the present invention is recovery of hydrocarbons from carbonaceous resources having limited mobility and/or recoverability under normal formation conditions, it is appropriate to liquid petroleum formations as well. While not limited to solids (such as oil shale and other kerogen-containing deposits) or high-viscosity oil and tars, the present invention focuses on these as models of what is generally referred to herein as substantially immobile (or fixed-bed) carbonaceous materials or formations.
Methods for developing formations containing substantially immobile hydrocarbon deposits often fail the test of practicality because they are not: a) effective at achieving high volumetric productivity, b) flexible with respect to in situ hydrocarbon chemistries and recovery methods, c) predictable and effective across a broad range of common geological formations, and/or d) compatible with the effective protection of the surrounding environment and/or ecosystems. Nevertheless, recovering carbon and hydrocarbon products without costly and complex mining operations remains a desirable objective. As discussed elsewhere herein, the methods of the present invention focus broadly on the mobilization, fluidization, and in situ modification of carbonaceous deposits so as to provide an efficient means of producing fluid hydrocarbon products. Accomplishing this objective may require methods that elicit limited, but important changes in the chemical structure and/or physical state of the deposited resource within the formation. Practical methods that enable systematic development and fluidization of a variety of different fixed-bed hydrocarbons resources could prove particularly important in both chemical and fuel industries. To achieve material fluidity, such methods may include defined, in situ chemical reactions, as well as changes in chemical composition, solubility, density, viscosity, phase, and/or physical partitioning of the hydrocarbon material within the formation. For the purposes of this invention a fluid may be, but is not limited to, a gas, a liquid, a supercritical fluid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow.
The present invention addresses the in situ transformation and recovery of energy and chemical products from subterranean carbonaceous formations. The methods of this invention comprise a means of producing fluid hydrocarbon from formations comprising one or more FBCD, and for extending unusual levels of protection to the surrounding environment by a combination of aquifer management methods, low-impact surface processing facilities, and a low-density distribution of surface wells and equipment. The invention further comprises both methods and systems that enable physico-chemical transformation of a wide range of carbon-rich deposits, and the recovery of these produced materials. Such materials may be useful as basic fuels, chemicals products, intermediates and other classes of product. These products largely comprise saturated and unsaturated, non-aromatic hydrocarbons, although aromatic and other non-hydrocarbon products may be produced in abundance. Molecular hydrogen, for example, may be generated via these methods, as may high levels of aromatic hydrocarbons under certain conditions.
The methods of this invention apply to any carbon-rich geological formation, including but not limited to those containing deposits of: kerogen; bitumen; lignite; coal (including brown, bituminous, sub-bituminous and anthracite coals); liquid petroleum; depleted oil fields; tar or gel phase petroleum; and the like. While applicable to liquid hydrocarbon formations, preferred applications include those wherein the carbonaceous materials are either mineralized (e.g. largely fixed in position), highly viscous, or rendered substantially immobile by entrainment in soils, sands, tars and other geologic materials. For the purposes of this invention, all of these embodiments are said to represent fixed-bed hydrocarbon formations (FBHFs). The carbonaceous material itself may be referred to as fixed-bed hydrocarbon (FBH) even though it may exist in many forms, such as a soil-entrained fluid, a high-viscosity gel or fluid (e.g. tar), a mineralized, non-hydrocarbon solid (e.g. kerogen, lignite, coal, etc.). Formations containing deposits such as these may be found at depths ranging from surface formations to tens of thousands of feet. A FBHF may be found both under both land and sea surfaces.
Some fixed-bed hydrocarbon formations occur as relatively simple deposits of a single thick seam of carbonaceous material. Others, may be more complex in configuration. Although some of these deposits have been well characterized, practical methods for targeting and developing their carbon-rich deposits are lacking in the art. In situ methods for developing and producing such carbonaceous structures are highly desirable.
For the purposes of this invention, it is instructive to consider one type of carbonaceous formation—the well-characterized oil shale beds of N.W. Colorado. While not wishing to be bound by theory, it has been suggested that, at the time of deposition, some of the precipitating dolomitic marlstones present in the Piceance Basin of Colorado, simultaneously acquired relatively high kerogen content and also relatively high content of soluble sodium minerals, such as nahcolite, dawsonite, and halite. In some portions of the Piceance Basin, these water-soluble sodium minerals may have been dissolved, resulting in greatly increased porosity and permeability of these oil-shale beds, and forming, over time, which then become significant aquifers within the oil-shale zones. The removal of these soluble salts, by water-flow leaching seems to have created large voids or cavities which at times may have collapsed, resulting in brecciation of the rock. Those of skill in the art will note that zones formed in such a manner might often exhibit very high-permeability. Indeed, the stratagraphic mapping of the Piceance Basin oil shale beds reveal some layers having very high permeability (i.e., multi-Darcy) aquifers, consistent with this model and others having lower permeability.
Other portions and strata of the Piceance Basin exhibit different properties than those described above. For example, the Mahogany Zone occurs near the top of the oil-shale section, and is marked by a much lower content of soluble minerals than those observed in the permeable zone(s). A lower content of soluble minerals results in less material available for leaching to form aquifers. Such oil-shale zones, especially the Mahogany Zone, will tend to have very low permeability with very few, if any, significant aquifers.
On average, the oil-shale section of the Uinta Basin in N.E. Utah exhibits fewer and thinner carbonaceous beds than the Piceance Basin formation. According to geological theory, this is consistent with a scenario in which the layers of the Utah formation were deposited with lower content of soluble minerals, resulting in less subsequent leaching and less development of permeable aquifers in the oil-shale section. Both low and high permeability zones are important targets for development of chemical and hydrocarbon production methods. However, the few ex situ methods or in situ methods of oil shale development examined to date favor the less permeable materials over the more permeable ones.
In the geologies often observed in coal, lignite and petroleum formations, the presence of high permeability water saturated aquifers is most often seen as a liability that limits successful development. In contrast, low permeability boundaries surrounding the carbonaceous or hydrocarbon resources is often seen as an essential factor in successful extraction of heavy oil, and tar sand formations.
A systematic set of tools for enabling the in situ development of both high and low permeability zones is an important, ongoing and often critical need in the art of hydrocarbon production from, depleted, conventional and unconventional carbonaceous geological resources.
A variety of methods for heating formation fluids so as to initiate a hydrocarbon recovery process are described in the art. For examples, several inventions utilize downhole heaters and are illustrated in U.S. Pat. No. 2,634,961 to Ljungstrom, U.S. Pat. No. 2,732,195 to Ljungstrom, U.S. Pat. No. 2,780,450 to Ljungstrom, U.S. Pat. No. 2,789,805 to Ljungstrom, U.S. Pat. No. 2,923,535 to Ljungstrom, and U.S. Pat. No. 4,886,118 to Van Meurs et al. Other inventions showing downhole combustion chambers are illustrated in U.S. Pat. No. 4,397,356 to Retallick and U.S. Pat. No. 4,442,898 to Wyatt. Each of the patents cited in this paragraph are incorporated by reference as if fully set forth herein.
Recently, methods have been developed to facilitate the processing of oil shale and entrenched subterranean hydrocarbon. A series of patents issued to the Shell Oil Company since November 2002 (U.S. Pat. Nos. 6,880,663; 6,485,232, 6,581,684, 6,588,504, 6,591,906, 6,591,907, 6,607,033, 6,609,570, 6,698,515, 6,702,016, 6,708,758, 6,712,135, 6,712,136, 6,712,137, 6,715,546, 6,715,547, 6,715,548, 6,715,549, 6,722,429, 6,722,430, 6,725,920, 6,725,921, 6,725,928, 6,729,395, 6,729,396, 6,729,397, 6,729,401, 6,732,794, 6,732,796, 6,739,393, 6,739,394, 6,742,587, 6,742,588, 6,742,593, 6,745,831, 6,745,837, 6,749,021, 6,752,210, 6,758,268, 6,761,216, 6,769,483, 6,769,485, 6,880,663, 6,915,850, 6,918,442, 6,918,443, 6,923,257, 6,929,067, 6,951,247, 6,991,032, 6,991,033, 6,994,169, 6,997,518, 7,004,247, 7,004,251, 7,013,972, 7,032,660, 7,040,397, 7,040,399, 7,051,811) issued to a series of inventors listed here as Wellington et al.; Vinegar et al.; de Rouffignac et al.; and Zhang et al.) describe the use of a variety of downhole heaters to accomplish the in situ retorting of oil shale. Because these patents deal largely with a single subject matter by an affiliated group of inventors, they are referred to generally herein as the “Shell Series”. This series constitutes the bulk of the recent work on in situ retorting of oil shale. As is evident in the ensuing pages, the in situ retorting and hydrocarbon processing methods of the present patent are quite distinct from the methods described in this series of this disclsures. The Shell Series is incorporated herein by reference as if fully set forth herein.
While patents listed in the paragraph above seem to describe a number of concepts for producing hydrocarbons from oil shale deposits, the methods offer limited utility and practicality for a number of reasons. First, the oil shale methods described in the Shell Series rely largely on use of radiant and conductive well-bore heaters for the purpose of heating an oil shale formation by thermal conductivity from the well bore walls outward into the surrounding rocks. These well-bore heaters are understood to be largely fixed in a geometry defined by that of a given (heater) well-bore. Second, the preferred heaters are understood to be electrically-powered heating elements of various design and dimensions. The consequence of using such devices is likely to be an enormous, impratical electrical energy demand and associated cost. Third, the formation development strategies (e.g. density of individual heater wells required), and the limited heat-penetration offered by such methods suggests that these methods may be appropriate only for heating of very high organic content, low-permeability oil shale deposits. Fourth, the application of the above methods seem to be limited to those that are substantially dewatered such as by a series of water production and/or water recovery wells. Fifth, the practical operation of such methods seems to require establishment of a solid physical diffusion barrier between the treated zone and the surrounding formation and aquifers. In particular, this barrier seems to be provided primarily through construction of a freeze-wall containment system. Sixth, the establishment of a freeze-wall containment system represents yet another energy-intensive operation likely to require extraordinary quantities of injected refrigerant or additional electrical energy.
Other important work in the field is described in U.S. Pat. Nos. 6,588,503, issued in 2003 to Karanikas et al.; 6,742,589, issued in 2004 to Berchenko et al.; 6,763,886, issued in 2004 to Schoeling et al.; 6,736,215, issued in 2004 to Maher et al.; 6,719,047, issued in 2004, Fowler et al.; and 6,722,431, issued in 2004 to Karanikas et al. These patents also describe important aspects of the present art related to methods for producing and recovering hydrocarbon products from oil shale formations (e.g. one class of FBHF). Each of these patents is set forth herein by reference as if fully set forth herein.
Application of heat (usually in the form of steam) is well known in conventional liquid petroleum recovery operations. As practiced, however, such methods have had only limited success in enhancing recovery of oil and hydrocarbons from depleted and heavy oils fields, and even more limited success or enhancing fluid production from other types of carbonaceous deposits. The limited success may be due to in part to the, complex interfacial barriers that exist in multi-phase fluids, especially when they are partially entrained within a solid-phase (e.g. mineral) matrix. The nature of these interfacial effects is described elsewhere in this disclosure.
Although the methods have proven uneconomical, there have been sporadic attempts, and even some technical success, in producing fuel hydrocarbons by in situ heating of oil shale deposits. Some such methods are described in U.S. Pat. No. 2,923,535 to Ljungstrom and U.S. Pat. No. 4,886,118 to Van Meurs et al. Each of these patents is set forth herein by reference as if fully incorporated herein. In some processes disclosed by Ljungstrom, for example, an oxygen containing gaseous medium is introduced to a permeable stratum, preferably while still hot from a preheating step, to initiate combustion. More recent disclosures (e.g. the Shell Series, etc. . . . ) illustrate other concepts for heating oil shale formations using well bore-based heating elements.
In several methods described in the previous several paragraphs, heat is applied for the purpose of lowering viscosity and increasing flowability of formation fluids. In some oil shale methods, heat is used to pyrolyze a solid to release a fluid hydrocarbon. Thus, the heat is used substantially to release formation fluids from formation solids without eliciting substantial changes in the chemical identities of said fluids once mobile (e.g. transformations in chemical structures due to one more intra- or inter-molecular chemical reactions).
While some of the methods listed above describe a general concept of producing differential hydrocarbon populations from oil shale, and perhaps other liquid hydrocarbon-containing formations, the methods do not provide systems for producing formation fluids highly enriched in any specific olefin or paraffin fraction in response to operator input or instruction. Such methods would be of considerable value in the field. The proceeding methods provide little technical guidance toward producing a substantially more defined natural gas or petroleum product than would be typical, for example, of a light- or middle distillate petroleum stream. One aspect of the instant invention is a method for controlling, directing and/or recovering substantially defined distributions of hydrocarbon products from oil shale and other FBH formations.
A variety of methods have been described for heating an oil shale or liquid hydrocarbon formation. Electric heaters may be used to heat a subterranean formation by radiation and/or conduction. For example, an electric heater may resistively heat an element. U.S. Pat. No. 2,548,360 to Germain, which is incorporated by reference as if fully set forth herein, describes an electric heating element placed within a viscous oil within a well bore. The heater element heats and thins the oil to allow the oil to be pumped from the well bore. U.S. Pat. No. 4,716,960 to Eastlund et al., which is incorporated by reference as if fully set forth herein, describes electrically heating tubing of a petroleum well by passing a relatively low voltage current through the tubing to prevent formation of solids. U.S. Pat. No. 5,065,818 to Van Egmond, which is incorporated by reference as if fully set forth herein, describes an electric heating element that is cemented into a well borehole without a casing surrounding the heating element.
U.S. Pat. No. 6,023,554 to Vinegar et al., which is incorporated by reference as if fully set forth herein, describes an electric heating element that is positioned within a casing. The heating element generates radiant energy that heats the casing. A granular solid fill material may be placed between the casing and the formation. The casing may conductively heat the fill material, which in turn, may conductively heat the formation.
U.S. Pat. No. 4,570,715 to Van Meurs et al., which is incorporated by reference as if fully set forth herein, describes an electric heating element. The heating element has an electrically conductive core, a surrounding layer of insulating material, and a surrounding metallic sheath. The conductive core may have a relatively low resistance at high temperatures. The insulating material may have electrical resistance, compressive strength, and heat conductivity properties that are relatively high at high temperatures. The insulating layer may inhibit arcing from the core to the metallic sheath. The metallic sheath may have tensile strength and creep resistance properties that are relatively high at high temperatures.
U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated by reference as if fully set forth herein, describes an electrical heating element having a copper-nickel alloy core.
Combusting a fuel is most often more economical than using electricity to heat a formation. Combustion of a fuel may be used in a variety of ways to heat a formation. Several different types of heaters may use fuel combustion as a heat source that heats a formation. The combustion may take place in the formation, in a well, on or near the surface. Combustion in the formation may be by way of a fireflood. An oxidizer may be pumped into the formation. The oxidizer may be ignited to advance a fire front towards a production well. Oxidizer pumped into the formation may flow through the formation along permeable/porous zone or fracture lines in the formation. Ignition of the oxidizer may not result in the fire front propagating through the formation. Indeed the traditional fireflood and fire front propagates through a reservoir primarily by penetration of the fire front into the permeable/porous zones and fractures of the formation, and then indirectly by convection. The methods disclosed later in this invention provide for a more uniform and controlled heating of a formation, or a segment of a formation, through use of a mobile heat source.
A mobile heat stream comprising one or more heat transfer fluids, may also be generated by heating in, at, on or through a surface heat source. For example, heat may be transferred to a mobile injectable fluid or vapor via a surface heater in which combustion gases are burned, primarily for the purpose of achieving heat transfer prior to injecting the mobile agent. Alternatively, the combustion gases themselves can be circulated from a surface source through well bores to heat the formation. Examples of fired heaters, or surface burners that may be used to heat a subterranean formation, are illustrated in U.S. Pat. No. 6,056,057 to Vinegar et al. and U.S. Pat. No. 6,079,499 to Mikus et al., which are both incorporated by reference as if fully set forth herein.
A flameless combustor may be used to combust a fuel within a well. U.S. Pat. No. 5,255,742 to Mikus, U.S. Pat. No. 5,404,952 to Vinegar et al., U.S. Pat. No. 5,862,858 to Wellington et al., and U.S. Pat. No. 5,899,269 to Wellington et al., which are incorporated by reference as if fully set forth herein, describe flameless combustors. Flameless combustion may be accomplished by preheating a fuel and combustion air to a temperature above an auto-ignition temperature of the mixture. The fuel and combustion air may be mixed in a heating zone to combust. In the heating zone of the flameless combustor, a catalytic surface may be provided to lower the auto-ignition temperature of the fuel and air mixture.
Methods disclosed by McQueen et al. in U.S. Pat. No. 7,048,051 describe a heating process whereby a hole is drilled into an oil shale formation and a processing gas inlet conduit is positioned within the hole so as to allow injection of the heated gas into the formation to create a thermal energy front and allow for conversion of kerogen into hydrocarbonaceous products, the products are harvested from an effluent gas conduit positioned in the same well bore. The method appears to use a thermal conductivity a well bore as the means to heat the formation and produce retorted fluid through the same well bore that is used to heat the oil shale. In these and other aspects, the method appears to lack utility for continuous production and efficient heating of a formation.
A variety of alternative physical and or chemical treatments may be used to heat a formation as part an oil shale and/or hydrocarbon retorting process. Work conducted by Phillips Petroleum and others, shows that acoustic tools can be used to enhance oil recovery in secondary and tertiary recovery operations. While methods for acoustic excitement vary widely, they generally involve a variable frequency signal generator in or near the injection and/or producing wells. U.S. Pat. No. 7,048,051 contains a brief description of the use of an acoustic vibration to enhance recovery of products from oil shale. In one embodiment, this patent comprises the use of acoustic tools to enhance the release of hydrocarbonaceous products from a kerogen-containing formation as thermal energy carrier fluid passes from an injection well toward a producing well. The vibration will primarily affect the mobility of hydrocarbon materials that have become liquefied. It is less likely to have dramatic effects on the mineralized, still-immobile carbonaceous compounds.
Microwave energy has also been disclosed as a means of obtaining hydrocarbon fuels from oil shale and oil sand formations. U.S. Pat. No. 4,419,214 to Balint, et al., describes a method of separating bitumen and tars from shale oils and tar sands through the use of microwave treatment of feedstock under pressure and in the presence of chlorinated-fluorinated hydrocarbons, carbon tetrachloride and chloroform. In U.S. Pat. No. 4,153,533, Kirkbride teaches a process for recovering oil from shale through the microwave irradiation of feedstock under high pressure and in the presence of hydrogen and water vapor. It is taught that the moisture content of the feedstock is to be kept below 3% while the process includes the drying of the feed shale oil particles. It is further noted that Canadian Patent No. 1,308,378 to Philippe teaches separating bituminous materials from tar sands through the use of gravity. The tar sands are treated by microwave irradiation in the presence of water. Separation of the bituminous fractions from the mineral fractions by gravity takes place at temperatures less than the boiling point of water. Each of the patents cited here are incorporated herein by reference as if fully set forth herein.
In addition to the microwave methods described above, it is noted that a number of patents describe the application of microwave energy for heating oil shale, tar sand and similar hydrocarbon sources. For example, microwave energy was used to retort feedstock in U.S. Pat. No. 2,543,028 to Hodge, in U.S. Pat. Nos. 3,449,213 and 3,560,347 to Knapp and in U.S. Pat. No. 3,503,865 to Stone. U.S. Pat. No. 4,408,999 to Nadkarni treats the oil shale and coal under microwave irradiation in an acidic slurry to assist the solution of the mineral components. Each of these patents are incorporated herein by reference as if fully set forth herein. These vibrational and microwave methods may be used beneficially for enhancing mobilization or heating of formation hydrocarbons in the present invention, and/or for enhancing product composition and production efficiency.
In spite of the disclosure, the methods described above have not been embraced commercially. In general, they do not yield hydrocarbon products that are economically competitive with natural crude oil. Those processes which employ the use of microwave energy require the high consumption of electrical energy for implementation. Microwave energy is absorbed by water, a substance exhibiting extremely high dielectric losses. The same microwave energy is often times employed for the heating and evaporation of water, again, resulting in an economically uncompetitive process. Further energy losses arise from the heating of the rock and sand sources while only a small fraction of the microwave energy is applied to the oils themselves.
US Patent Publication No. 20040031731 discloses a method whereby metal oxide sensitizers are used as intermediate transfer agents to facilitate transfer of microwave energy to oil shale and tar sand materials do facilitate cracking. This application is hereby incorporated fully by reference as if set forth fully herein.
While instructive, the foregoing methods neither contemplate nor describe the in situ application of microwave energy to facilitate or otherwise supplement the combined kerogen pyrolysis and hydrocarbon cracking that comprise an important aspect of the present invention.
Synthesis gas may be produced in reactors or in situ within a subterranean formation. Synthesis gas may be produced within a reactor by partially oxidizing methane with oxygen. In situ production of synthesis gas may be economically desirable to avoid the expense of building, operating, and maintaining a surface synthesis gas production facility. U.S. Pat. No. 4,250,230 to Terry, which is incorporated by reference as if fully set forth herein, describes a system for in situ gasification of coal. A subterranean coal seam is burned from a first well towards a production well. Methane, hydrocarbons, H.sub.2, CO, and other fluids may be removed from the formation through the production well. The H.sub.2 and CO may be separated from the remaining fluid. The H.sub.2 and CO may be sent to fuel cells to generate electricity.
U.S. Pat. No. 4,057,293 to Garrett, which is incorporated by reference as if fully set forth herein, discloses a process for producing synthesis gas. A portion of a rubble pile is burned to heat the rubble pile to a temperature that generates liquid and gaseous hydrocarbons by pyrolysis. After pyrolysis, the rubble is further heated, and steam or steam and air are introduced to the rubble pile to generate synthesis gas.
U.S. Pat. No. 5,554,453 to Steinfeld et al., which is incorporated by reference as if fully set forth herein, describes an ex situ coal gasifier that supplies fuel gas to a fuel cell. The fuel cell produces electricity. A catalytic burner is used to burn exhaust gas from the fuel cell with an oxidant gas to generate heat in the gasifier.
Carbon dioxide may be produced from combustion of fuels, such as may be used for generating heat in the present inventions, as well as many prior art inventions in the area of oil, gas and carbonaceous formation development. Carbon dioxide may also be produced from combustion of formation fluids and from many chemical processes. Carbon dioxide may be used for various purposes, such as flooding of a depleted oil field, or for use in enhanced oil recovery. Similarly, it may be used in coal bed demethanation to recover high-methane natural gas(es). It may also be used as a feed stream for a dry ice production facility, as a supercritical fluid in a low temperature supercritical fluid process, and in many other industrial and commercial applications. Although some carbon dioxide is productively used, many tons of carbon dioxide are vented to the atmosphere. Additional uses of process-derived carbon dioxide may be required to make such methodologies widely useful. The instant invention incorporates these and other important uses of process-derived carbon dioxide
Recent work by Wellington et al, (U.S. Pat. No. 6,880,633, and other Shell Series patents) teach that hydrocarbons may be generated from oil shale formations via in situ heating. One of skill in the art may find that the development plan, heating and recovery methodologies provided in these disclosures prove to be limited, cumbersome, and/or cost-prohibitive. As proposed in these inventions a heater(s) or heat source(s) provide heat to the formation primarily by conductive and/or radiative heat transfer from a well bore-confined heating element. The examples provided allow for the heat source to include electric heaters such as an insulated conductor, elongated member, and/or a conductor disposed within a conduit, and the like. The heaters are said to include those that generate heat by burning a fuel, although little guidance is given to enable use of such heaters. These “heaters” are described as forming a template within a formation that progressively heats the formation, through a radiative conduction process centered locally on each of those well bore heat sources. As described later, the present invention employs a very different strategy for heating a formation and producing hydrocarbon and chemical products from oil shale and other formations.
Other distinctives that limit the utility of the methods proposed in the Shell Series include: a) targeting of low water, low permeability, and low hydrogen formations; b) use of costly, slow stepwise heating to evaporatively removal of water prior to initiation of pyrolysis; c) preference for formation temperatures of about 480-750 degree F. to provide desired hydrocarbons, d) limited control of formation chemistry; e) limited capacity to address specific formation geology (e.g. target differing strata using differing techniques) and/or use formation permeability differences to advantage, and f) use of a freeze-wall, solid wall aquifer containment system. Methods and systems provided in our detailed description are distinct from prior inventions in these and many other respects.
Carbon mobilization from a FBHF most often requires a degree of pyrolysis. Generally, this is understood to require temperatures at or above about 480-520 degree F. For the purposes of the present invention, any pyrolysis-based mobilization of hydrocarbons or related compounds from mineralized or otherwise low mobility geological carbon deposits is included in the general use of the term “retorting”.
Traditionally, the proposed methods for retorting oil shale were largely above-ground (e.g. surface) operations. Such retorting of oil shale would typically involve mining followed by a surface pyrolysis process in which kerogen-containe rocks are burned at temperatures of >750 degree in a vessel from which liberated hydrocarbons may be recovered for use as combustion fuels, and oils. The quality of the oils produced from such retorting processes are typically been quite poor and would require costly upgrading in a commercial operation. Because of the required mining, transport and processing, aboveground retorting is seen as having a profoundly adverse impact on environmental and water resources. Many U.S. patents have been issued relating to aboveground retorting of oil shale. Currently proposed above-ground retorting processes include, for example, direct, indirect, and/or combination heating methods. Of these, none have proven to be commercially viable.
Except for coals, which are mined and burned directly as fuel, a similar history of costly and complex process development and capital requirements have limited development of ex situ strategies for retorting (e.g. pyrolyzing) or otherwise mobilizing other fixed-bed carbonaceous resources.
Below-ground, or in situ methods for retorting oil shale have also been proposed. While long-envisioned, practical and non-catastrophic in situ retorting of oil shale (e.g. in the form of kerogen) remains a largely elusive goal. In situ retorting involves retorting oil shale without removing the oil shale from the ground by mining. In practice, however, moderate success has been reported only in “modified” in situ process in which retorting is enabled through an underground process that produces cavernous subterranean retort chambers. An example of a “modified” in situ process includes a method developed by Occidental Petroleum that involves mining approximately 20% of the oil shale in a formation, explosively rubblizing the remainder of the oil shale to fill up the mined out area, and combusting the oil shale by gravity stable combustion in which combustion is initiated from the top of the retort. Other examples of “modified” in situ processes include the “Rubble In Situ Extraction” (“RISE”) method developed by the Lawrence Livermore Laboratory (“LLL”) and radio-frequency methods developed by IIT Research Institute (“IITRI”) and LLL, which involve tunneling and mining drifts to install an array of radio-frequency antennas in an oil shale formation.
As for ex situ methods, in situ retorting and fluidization opportunities exist for a wide range of substantially immobile carbonaceous resources. (e.g. FBCD). With the exceptions of coal gasification, oil shale retorting and secondary oil recovery, however, the methods remain largely undeveloped and unexplored.
For continiuous production, true in situ retorting of oil shale and other FBCD requires the development of a formation such that there is substantial communication of materials between wells. Because work on oil shale has been in done in largely impermeable formations, obtaining permeability within an oil shale formation (e.g., between injection and production wells) has tended to be difficult and cost-prohibitive. Many methods have attempted to link injection and production wells, including: hydraulic fracturing such as methods investigated by Dow Chemical and Laramie Energy Research Center; electrical fracturing (e.g., by methods investigated by Laramie Energy Research Center); acid leaching of limestone cavities (e.g., by methods investigated by Dow Chemical); steam injection into permeable nahcolite zones to dissolve the nahcolite (e.g., by methods investigated by Shell Oil and Equity Oil); fracturing with chemical explosives (e.g., by methods investigated by Talley Energy Systems); fracturing with nuclear explosives (e.g., by methods investigated by Project Bronco); and combinations of these methods. As is apparent in examples found later in this document, such methods might also be employed to advantage in in the present invention. Many of such methods, however, have relatively high operating and environmental costs and lack sufficient injection capacity.
In contrast, the methods presented in detail later in this invention comprise the use of thermal-energy carriers to retort fixed-bed carbon materials in high-permeability formations, such as are often associated with coal and lignite deposits. However, the methods also comprise the effective retorting of oil shale from high permeability oil shale formations, such as those described in the Piceance Basin in N.W. Colorado; and to a lesser extent in the N.E. Utah (e.g. Lake Uinta), and the Washakie and Green River Basins in S.W. Wyoming (e.g. Lake Gosiute). Moreover, the methods of the present invention address cost-effective means of introducing and using to advantage formation permeability, whether natural or artificially induced. Also, the methods of the present invention provide for controllably propagating hydraulic fractures, and for creating high permeability, propped fractures in the formation. Such methods often provide an inexpensive means to introduce additional permeability into any FBHF when desired.
One proposed in situ retorting process is illustrated in U.S. Pat. No. 3,241,611 to Dougan, assigned to Equity Oil Company, which is incorporated by reference as if fully set forth herein. In it, Dougan discloses a method involving the use of natural gas for conveying kerogen-decomposing heat to the formation. The heated natural gas may be used as a solvent for thermally decomposed kerogen. The heated natural gas exercises a solvent-stripping and retorting action with respect to the oil shale through creating new retorted porosity and local permeability around the injection well bore. By increasing the injection pressure, the heated natural gas is pushed further into the newly created retorted pore spaces to produce decomposition product vapors and gases. Then, when the injection pressure is decreased, these retorted vapors and gases and the injected natural gas expand and flow back into the production portion of the same well bore for production flow to the surface. The pulsed sequence of high pressure injection of heated natural gas into the retorted pore spaces followed by low pressure production of this natural gas plus newly formed retorted shale oil vapors and gases is accomplished through a single well bore. Certain methods of this patent may prove useful in the operation of the present invention.
Barriers that serve to limit of formation fluids and solutes from an area being actively treated are important in the operation of the present invention. A number of useful barrier development, biological degradation and adsorption methods are known in the art that may be of relevance in the methods of this invention. For examples, U.S. Pat. No. 5,297,626 Vinegar et al. and U.S. Pat. No. 5,392,854 to Vinegar et al., which are incorporated by reference as if fully set forth herein, describe a process wherein an oil containing subterranean formation is heated. The following patents related to this subject are incorporated herein by reference: U.S. Pat. No. 6,152,987 to Ma et al.; U.S. Pat. No. 5,525,322 to Willms; U.S. Pat. No. 5,861,137 to Edlund; and U.S. Pat. No. 5,229,102 to Minet et al. These patents disclose valuable methods that can be employed to advantage in the present invention.
U.S. Pat. No. 5,018,576, issued to Udell et al., describes a method for decontaminating subsurface soil and groundwater using a combination of steam injection wells and sub-atmospheric extraction wells. As described, the method is useful for the decontamination of subsurface environments containing volatile contaminants and nonvolatile water-soluble contaminants, as well as some non-aqueous, non-volatile contaminants. In the methods of the patent, steam injection is intermittent and/or otherwise stopped for some or all of the extraction (volatilization and collection) phase. As presented, the method is largely described as a means of removing unwanted environmental contaminants resulting largely from human activity. Specifically, the patent addresses the release of entrained, trapped water and contaminants from soil after cessation of steam injection. This patent is incorporated in its entirety herein by reference for all purposes. The methods disclosed therein provide several aquifer containment methodologies for use in conjunction with the water and aquifer management methods of this invention.
U.S. Pat. Nos. 4,761,225 and 4,832,122 further disclose methods for removing hydrocarbons from groundwater and/or otherwise decontaminating a water table using a variety of extraction wells and heat, fluid and/or gas injection methods. In the '122 patent methods are specifically disclosed for injecting a fluid or gas upwardly through a contaminated zone so as to facilitate withdrawal of water through an extractor. These systems and methods are employed in this invention for controlling and purifying aquifer-associated water in the context of heat-based hydrocarbon recovery from oil shale(s) and other geological formations. The methods disclosed therein provide additional barrier development and aquifer treatment methodologies used in conjunction with the methods of this invention. Both of these patents are incorporated herein by reference as if set forth fully herein.
U.S. Pat. No. 6,224,770, issued to Savage et al., provides for the bioremediation of a hydrocarbon-contaminated groundwater by creating a sub-surface bioreactor. This patent discloses the use of sub-surface bioreactors to create a biological “wall” (or “bio-curtain”) in which migrating hydrocarbon contaminants can be trapped and biologically degraded. Although many methods exist for creating a subsurface bio-curtain, the '770 patent is illustrative of both the general principles and a specific methodology for doing so. Thus, it is incorporated herein by reference, in its entirety, for all purposes.
A wide variety of microbiological strategies for in situ bioremediation are known in the art. Some methods combine ex situ cultivation and conditioning with aquifer injection of microbial cultures. A variety of methods useful for ex situ and in situ bioremediation are disclosed in U.S. Pat. Nos. 4,992,174; 5,486,291; 4,649,114; and 4,661,458. Each of these patents, is hereby incorporated by reference in its entirely for all purposes. Even so, it is understood that many other methods for microbial cultivation, injection, selection, aeration, propagation, etc. are also known to those of skill in the art of environmental bioremediation. Together, these patents and methods provide a means of aquifer moisture containment and/or development of effective biological barriers or in situ bio-treatment methods that may be particularly useful in developing these aspects of the present invention.
U.S. Pat. No. 6,679,326, issued to B. Zakiewicz, in 2004, describes the creation of a high pressure fluid barrier forming an enclosure boundary in a fluidizable mineral or hydrocarbon production operation with respect to an overburden and floor strata that are separated by one more layers of production strata. As described in the '326 patent, the method comprises the confinement of a deposit by high pressure fluid barrier forming an enclosure boundary with respect to overburden and floor strata separated by one or more production strata containing desirable fluidizable deposits and/or potential reaction materials with simultaneous action of rubbilization (reduction of a “rocky”, large particle, or largely continuous solid material to smaller, more discontinuous material, such as rubble), mineral fluidization and dynamic-turbulent, centripetal displacement of fluidized minerals from the boundary strata of the mining field towards a collecting point. the methods of this invention may employ, for example, methods substantially similar to methods analogous to those shown for the Super Daisy Shaft, or similar technology In the '326 patent.
U.S. Pat. No. 6,679,326, issued to B. Zakiewicz, in 2004, describes the creation of a high pressure fluid barrier forming an enclosure boundary in a fluidizable mineral or hydrocarbon production operation with respect to an overburden and floor strata that are separated by one more layers of production strata. As described in the '326 patent, the method comprises the confinement of a deposit by high pressure fluid barrier forming an enclosure boundary with respect to overburden and floor strata separated by one or more production strata containing desirable fluidizable deposits and/or potential reaction materials with simultaneous action of rubbilization (reduction of a “rocky”, large particle, or largely continuous solid material to smaller, more discontinuous material, such as rubble), mineral fluidization and dynamic-turbulent, centripetal displacement of fluidized minerals from the boundary strata of the mining field towards a collecting point. The methods of this invention may employ, for example, methods substantially similar to methods analogous to those shown for the Super Daisy Shaft, or similar technology in the '326 patent.
In addition to spiral flow-based containment, a wide variety of strategies exist for creating diffusion barriers for selected aquifers. In general, these methods involve the creation of a hydrodynamic “ridge”, past which solute flow is either prohibited or highly disfavored. In geological engineering terms, a hydrodynamic “ridge” is a region or segment of a formation displaying an elevated potentiometric surface. In a series of recent patents, Wellington et al., propose the freezing of formation water as means of prohibiting flow of hydrocarbons and other materials from a selected portion of an oil shale formation. Likewise, concrete encasement, or “walling-off” an area (e.g. as with clay or concrete barriers) has been used in the mining, petroleum, natural gas and other industries for diffusion and/or aquifer control. While these may provide an effective means of controlling moisture egress, the present invention favors less invasive hydrodynamic and other methods. As discussed in detail later, the present invention uses formation properties in combination with various hydrodynamic methods to establish elevated potentiometric surfaces that limit egress within the formation of retorted material from an active retort zone in a formation. Similar methods are used to allow one to limit egress of formation waters and other fluids from a treatment area.
By convention, crude oil and other formation-derived hydrocarbon materials are often collected and transported by pipe or vessel to a sophisticated, integrated refinery and chemical manufacturing facility. At such facilities hydrocarbons may undergo a wide range of catalytic and thermal chemical processing steps to produce the reformed fuels and chemical products most often associated with petroleum refining. The present invention describes methods by which at least a portion of the initial modification of hydrocarbon products may occur in situ.
While there are many variations on each of the following themes, conventional processes for petroleum fuel and petrochemical production consist of the following major operations:                1) in-field extraction of carbonaceous raw material;        2) collection and transport of crude material(s)        3) refining and reformation of fuel and chemical products        4) separation and segmentation of fuels and chemicals        5) extraction, processing, distribution and regeneration (e.g. of catalysts, etc. . . . )        
As surface operations, each of these are complex, capital and resource intensive operations. It is desirable to consolidate a plurality of these operations into an increasingly simple, integrated process, and preferably, into single subsurface unit operation. Such methods offer potentially enormous savings of time, money and other resources associated both, with developing a global scale petrochemical facility, and with developing a high-yield geological formation.
Hydrocarbon cracking refers to a variety of pyrolytic methods used industrially to produce lighter, lower molecular weight hydrocarbons from heavier, often more viscous materials. The art of petroleum cracking comprises a variety of reactor-based methods for using heat energy, catalysts, hydrogen, and/or other additives to split longer chain hydrocarbons (and related compounds) into smaller molecules. Industrially, most forms of cracking are applied to heavy petroleum feed. Thermal cracking of linear, branched and aromatic hydrocarbon materials is well described in the art. Typically, industrial processes run at temperatures in excess of 650 degree F., although some cracking does occur at lower temperatures as well. As a matter of practice, this sets the minimum boiling point of about 650 degree F. for the heavy materials that are to be subjected to thermal or catalytic cracking. At temperatures above 650 degree F. cracking may occur efficiently, even without catalyst. Petroleum cracking refers to the pyrolytic decomposition of hydrocarbon materials chains that occurs upon heating to extreme temperatures, often in excess of 900 degree F. However, addition of cracking catalyst can allow a greater extent of cracking to be achieved more readily. Under thermocracking conditions, pyrolytic efficiency continues to increase with temperature (e.g. resulting in increased level of splitting and chain desaturation of hydrocarbons and other compounds with C—C backbone) up to temperatures of about 2000-2200 degree F. As temperatures approach 2000 degree F., conditions begin to favor burning of hydrogen from hydrocarbons, resulting in deposition of a stable carbonaceous ‘coke’ material that is rich in aromatic carbon content and deficient in hydrogen. This so-called ‘coking’ process is observed, to some extent in all commercially used hydrocarbon cracking operations. In some kerogen deposits, and other carbonaceous formations, however, the maximum allowable temperature is more limited (e.g. about 1400 degree F.) due to the thermal instability and potential decomposition of the non-carbon components of mineral matrix, such as limestone, dolomite, and other materials.
Hydrocarbons liberated from a carbonaceous deposit may be subjected to a series of conditions that allow for conversion to higher value or more easily processed materials. These conversions are typically carried out, ex situ, in a series of surface petroleum refining and processing operations that are well known in the art of petroleum and petrochemical engineering. Such methods often include condensation, distillation and other separations based largely on boiling points of various fractions. Subsequently, a series of thermal and catalytic cracking methods may be applied to convert heavier and saturated hydrocarbon materials to lighter and less-saturated derivatives. For example, methods described elsewhere in this invention allow for certain, key refining steps to be conducted in situ. Hydrocarbon cracking represents the most important of these. As run under a variety of industrial and refining formats, the petroleum cracking processes are amenable to a wide range of operator-level and catalytic interventions that may alter rate, temperature, product distribution, coke formation, hydrogen production, olefin, aromatic hydrocarbon and/or light chain hydrocarbon production.
Thermal cracking of hydrocarbons has been recognized for over a century as a means to generate useful commercial chemicals and intermediates. Commercially, the first successful cracking process was developed and patented by W. M Burton. The process operated by batch processing in horizontal stills at 750 F and 75-95 psi. A decade or so later, Clark made important changes in Burton's process, allowing it to run continuously. Cross and Dubbs made further improvements in the continuous process to provide the earliest precursor to today's operationally-intense, continuous cracking processes.
Steam (or thermal) cracking may operate either catalytically and non-catalytically to generate a wide range of saturated, unsaturated and aromatic hydrocarbons, as well as molecular hydrogen. Typically thermal cracking operations require somewhat higher temperatures than their catalytically driven analogs.
Thermal cracking of petroleum typically yields a population of saturated (e.g. paraffins) and unsaturated straight-chain hydrocarbons (e.g. olefins) having lower carbon numbers than the parent compounds. Depending on reaction conditions, feed material, presence of impurities, catalysts, and other factors, cracking may yield various cyclic hydrocarbons, heterocyclic compounds, liquid fuels (e.g. gasoline), synthesis gas components, molecular hydrogen, and other chemical and fuel products. Industrially, the balance of products in a petroleum cracker is a critical parameter in managing refinery operations and economics.
Examining the course of development of petroleum cracking technology provides insight into distinct applications of the technology that are described elsewhere in this invention. The large scale, high temperatures, variable feedstocks and other operational challenges intrinsic to petroleum cracking made it a target for catalyst and process developers from its earliest days. Opportunities to increase cracking efficiencies (e.g. of heavy petroleum feedstocks), minimize formation of low-value products (e.g. the heavy tars, refinery “bottoms” stream), and/or increase the volumetric productivity of existing capital all attracted substantial research investment. Interest in vapor phase cracking, for example, emerged during World War I. The work progressed slowly until the late 1920s. By that point, the rapid growth of the automobile fuels market was creating a large demand for a high-quality, anti-knock gasoline. By the early 1930s, the work on vapor phase processing and the standard liquid processes led to creation of a mixed-phase process. This process would became widely used in commercial refineries until the 1940s.
As vapor and mixed phase cracking processes were developing (in the late 1920s), Eugene Houdry introduced several key principles of catalyst use and regeneration to those working on potential next-generation processes. His work would dramatically alter the future of petroleum refining. Like other experimenting with the use of catalysts Houdry was deeply frustrated by the rapid inactivation he observed under cracking conditions. He postulated that some or all of this inactivation might be reversible, by the removal of the carbonaceous “coke” from the catalytic materials. To test this hypothesis, he treated the catalysts at temperatures well in excess of cracking temperatures (e.g. >>1000 F) in an attempt to burn off the coke. When he did so, he found that substantial activity could be restored.
As with many advances in petroleum cracking, Houdry's results were met with initial skepticism. Questions surrounding the practicality and efficiency of catalyst regeneration and replacement were but a few of myriad operational concerns that were raised. By the late 1930s, however, many of the most important objections/concerns had been overcome, allowing for rapid emergence of a variety of semi-continuous and continuous catalytic cracking processes.
Initial catalytic cracking processes employed fixed bed catalysts, but these proved inadequate to produce the vast volume of liquid fuels required for the rapidly growing aviation and motor fuel markets. The development of moving bed reactors quickly followed. These allowed development of the first truly continuous catalytic cracking operations.
Today, catalytic cracking processes come in three distinct forms, including mixed-bed, fluid catalytic cracking (FCC); hydrocracking, using hydrogen to mediate reductive cracking, and oxidative cracking. Whereas all three methods employ catalysts, FCC uses powdered rather than pelleted catalyst particles. This is important for maintaining mobility under process conditions. While similar catalyst materials may be used in both hydrocracking and FCC, nowhere are the catalyst design requirements as arduous as in FCC. Typically, particles of <100 microns are required, and are kept afloat in a vapor phase by a sophisticated system of blowers within the reactor. Some key development stages and events and in the history of FCC technology are highlighted in the following table (adapted from W.R. Grace & Co.'s publication, “Guide to Fluid Catalytic Cracking, Volume 1”, 1993.). This history of catalytic cracking technology provides useful insight into application and potential limitations of the present invention.
Key Breakthroughs in the History of FCC Technology DevelopmentBreakthroughBy1st Thermal Cracking Operation EstablishedW.R Burtonca 1910Activated Clay Catalyst Used in CrackingE.G. Houdry1928Fluidizable Catalyst DevelopedExxon1942Synthetic Low Alumina CatalystGrace Davison1942Microspheroidal Catalysts DevelopedGrace Davison1948Synthetic High Alumina CatalystGrace Davison1955Spray-dried Zeolite CatalystMobil1964Ultra-stable Y (USY) Zeolite CatalystGrace Davison1964Silica-Sol Bound (Structured) CatalystsGrace Davison1973Platinum CO Combustion PromoterMobil1974Octane-selective CatalystGrace Davison1975Sb Nickel Passivation Method for CrackingPhillips1975CatalystAlumina-Sol Bound CatalystsGrace Davison1981ZSM-5 Octane (Catalyst) AdditiveMobil1986Bi Nickel Passivation Method for CrackingChevron1987CatalystUSY Zeolite w/ Enhanced Gasoline SelectivityGrace Davison1989Development of Custom Catalyst Matrix &Various1990sAssembly Methods
While not wishing to be bound by theory, the products of the cracking process and mechanistic studies conducted by numerous researchers are consistent with a free-radical mediated process. Generally, there is little preference for primary, secondary or tertiary carbons during free radical formation. This means that the product mix is typically a broad, complex distribution of compounds. For this reason, in the early stages of the in situ cracking process, the products generated can be even more diverse than the originating feedstocks. As the extent of cracking increases, however, the average hydrocarbon chain-length decreases progressively. When the hydrocarbon products reach an average carbon number of less than about 10, systemization and separation of discrete product streams becomes increasingly efficient and achievable. For example, the light-chain olefins, dry gas, wet gas, octane (e.g. gasoline) and other condensable streams begin to be produced in abundance.
Cracking of hydrocarbon feedstocks yields a variety of products depending, in part, on the nature of the feed. The principal cracking products generated from a variety of hydrocarbon feedstock hydrocarbons and cracking reactions can be summarized as follows.
FeedHydrocarbon(Predominant Reaction)ProductsParaffins(Chain Scission)Shorter Paraffins + OlefinsOlefins(Dehydrogenation + Scission)LPG Olefins(Cyclization)Naphthenes(Hydride Transfer)Paraffins(Isomerization + Hydride Transfer)Branched Olefins/Paraffins(Cyclization, Condensation +Coke (deposition)Dehydrogenation)Naphthenes(Scission)Olefins(Dehydrogenations)Cyclic Olefins + Aromatics(Isomerization)Various NaphthenesAromatics(Side-chain Scission)Olefins + UnsubstitutedAromatics(Transalkylation)Alkylaromatics(Dehydrogenation + Condensation)PolyaromaticsPolyaromatics(Alkylation + Dehydrogenation +CokeCondensation)
While far from exhaustive, this list serves to identify key categories of products likely under a variety of scenarios. For example, where feedstocks are heavy, as in tar sand and oil shale applications, the abundance of long-chain paraffins and heavy aromatics may predominate early. Upon further cracking, however, the chains will shorten, begin to favors olefins and lighter paraffins. Under the same conditions, substantial quantities of the heavier materials (e.g. multi-ring aromatics, etc.) will deposit as carbonaceous coke. Such coke may, however, be remobilized and recovered later in the operations as in situ thermal conditions become increasingly harsh.
Catalytic cracking is used most often as a downstream treatment for the high boiling petroleum distillation fractions. These fractions are often reduced to saturated linear and branched chain paraffins, naphthenes and aromatics. These materials are brought into contact with a one or more cracking catalysts, such as amorphous aluminum silicates or, more typically, crystalline aluminum silicates (e.g, zeolites), and other less common catalysts such as the manganese-based Houdry catalyst. The best performing zeolite catalysts are most often those containing rare earth cations present as catalyst stabilizers. Generally, the catalysts undergo inactivation by coking and must be subsequently regenerated. They often contain traces of platinum to assist with the conversion of carbon deposits to carbon dioxide during regeneration. In catalytic cracking operations, hydrocarbons are generally brought into contact with such catalysts at temperatures of >840-930 degree F. within a fluidized-bed catalytic cracker or a catalyst riser reactor.
Hydrocracking refers to the catalytic cracking of hydrocarbons in the presence of hydrogen. As with catalytic cracking, it is used industrially to partially pyrolize high boiling distillates into lower boiling products. Modern hydrocracking uses bifunctional metallic hydrogenation-dehydrogenation catalysts (e.g. Pd, Pt, C0-Mo) and acidic cracking components such as zeolites containing Al2O3-SiO2. The processes tend to run at temperatures of about 520 to 930 degree F. and about 1150-2900 psi, and require substantial capital investment both for hydrogen production and for the hydrocracking operation. Unlike other cracking operations, product streams from a hydrocracking unit operation usually contain little to no olefins, but they do tend to contain isobutane, naphtha, as well as fuel oil and gasoline components.
A large volume of art exists describing the development and operation of hydrocarbon cracking catalysts, either in the cat-cracking, fluid cracking, oxidative cracking, and other modes. However, little, if any, art exists describing the practical use of these catalysts and processes in conjunction with in situ retorting and conversion of FBH formations (such as oil shale, and others). Such methods are highly desirable.
The art of fluidized catalytic cracking (FCC) is particularly important. It has enjoyed great favor for decades in the field of petrochemical processing. A vast literature and product repertoire exists in this technology, making it possible for one of ordinary skill to identify catalyst products of value in a wide range of process settings. As used industrially, FCC is a method of choice for converting a heavy petroleum feedstocks into lighter, more valuable products such as high octane gasoline andor light olefins represent. In FCC, as with other catalytic cracking methods, pyrolysis occurs in the absence of externally added hydrogen. In industrial FCC operations, an inventory of excess catalyst is typically required so that used material may cycle between an active cracking reactor and a catalyst regenerator. Typically, a petroleum-based feed contacts 60-80 micron catalyst in a reactor at about 795 degree F.-1110 degree F., and usually 860 degree F.-1040 degree F. The hydrocarbons crack, and deposit carbonaceous coke on the catalyst. Cracked products are separated from the coked catalyst, which is stripped of volatiles, usually with steam, and then regenerated. In the catalyst regenerator, coke is burned, restoring catalyst activity and heating the catalyst to 930 degree F.-1650 degree F., usually 1110 degree F.-1380 degree F.
While a large number of catalysts will provide activity, the more moisture and coke resistant, the more likely the catalyst will provide sustained activity in the presence of a complex, flowing feedstock.
A thorough description of the catalytic cracking process may be found in the monograph, “Fluid Catalytic Cracking With Zeolite Catalysts”, Venuto and Habib, Marcel Dekker, New York, 1978, incorporated herein by reference. However, a brief review of some traditional and more recent discoveries pertaining to zeolite catalysts is helpful in assessing the type of catalyst that is most suitable for a given cracking operation. Most older FCC units regenerate spent catalyst in a single dense phase fluidized bed of catalyst. Although there are myriad individual variations, typical designs are shown in U.S. Pat. No. 3,849,291 (Owen) and U.S. Pat. No. 3,894,934 (Owen et al), and U.S. Pat. No. 4,368,114 (Chester et at.) which are incorporated herein by reference. Many newer units use high efficiency designs, with a fast fluidized bed coke combustor, dilute phase transport riser, and second dense bed to collect regenerated catalyst.
Because of their unique sieving characteristics, as well as their catalytic properties, crystalline molecular sieves and zeolites are especially useful in applications such as hydrocarbon conversion, gas drying and separation, and are particularly useful in the methods of this invention. Although many different crystalline molecular sieves have been disclosed, the chemistry continues to develop with suppliers such as W. R. Grace, Engelhard, Grace-Davison, UOP, and others providing ongoing innovation. For example, zeolites have desirable properties for gas separation and drying, as well as hydrocarbon and chemical conversions, and other applications. New zeolites may vary in their internal pore architecture, size, selectivity, and stability.
Typically, crystalline aluminosilicates are prepared from aqueous reaction mixtures containing alkali or alkaline earth metal oxides, silica, and alumina. Crystalline borosilicates are usually prepared under similar reaction conditions except that boron is used in place of aluminum. By varying the synthesis conditions and the composition of the reaction mixture, different, zeolites can often be formed.
In U.S. Pat. No. 6,881,323 (incorporated in its entirety herein by reference for all purposes), Zones (Chevron, USA, Inc) describes the latest development in a long line of SSZ-series zeolites developed for use in fluid catalytic cracking (FCC) operations and other applications. The patent provides both a process for converting hydrocarbons using the SSZ-54 catalyst as well as a description of its synthesis. Briefly, the catalyst comprises a zeolite having a mole ratio greater than about 20 of an oxide of a first tetravalent element to an oxide of a second tetravalent element which is different from the first tetravalent element, trivalent element, pentavalent element or mixture thereof and having, after calcination, has a defined X-ray diffraction pattern. A hydrocracking process using this catalyst comprises contacting a hydrocarbon feedstock under hydrocracking conditions with a preparation of SSZ-54 catalyst comprising the zeolite of this invention, preferably predominantly in the hydrogen form. The invention also includes a process for increasing the octane of a hydrocarbon feedstock to produce a product having an increased aromatics content comprising contacting a hydrocarbonaceous feedstock which comprises normal and slightly branched hydrocarbons having a boiling range above about 105 degree F. and less than about 390 degree F., under aromatic conversion conditions with a catalyst comprising the zeolite of this invention made substantially free of acidity by neutralizing said zeolite with a basic metal. Also provided in this disclosure is a process wherein the zeolite contains a Group VIII metal component.
While zeolites provide remarkable activity and stability, phosphorous stabilized structures often appear most suitable to the harsh conditions encountered in the in situ processes disclosed herein. FCC and other cracking catalysts are often said to be “stabilized” by addition of certain additives. For example, phosphorous content may be enhanced for stability. Zeolite ZSM-5 zeolite may be added for enhanced stability, productivity and selectivity. Moreover, phosphorous may be added to ZSM-5 containing catalysts. The result of such stabilization may be to produce a higher yield of light hydrocarbons and/or olefins than is produced with a catalyst composition that has not been stabilized by phosphorus. This comparison is normally made after deactivation with steam. Catalysts sold under trade name of OLEFINSMAXT™ (Grace Davison) are often enhanced in this manner. U.S. Pat. No. 5,110,776 teaches a method for preparing FCC catalyst comprising modifying the zeolite, e.g., ZSM-5, with phosphorus. U.S. Pat. No. 5,126,298 teaches manufacture of an FCC catalyst comprising zeolite, e.g., ZSM-5, clay, and phosphorus. See also WO 98/41595 and U.S. Pat. No. 5,366,948. Phosphorus treatment has been used on faujasite-based cracking catalysts for metals passivation (see U.S. Pat. Nos. 4,970,183 and 4,430,199); reducing coke make (see U.S. Pat. Nos. 4,567,152; 4,584,091; and 5,082,815); increasing activity (see U.S. Pat. Nos. 4,454,241 and 4,498,975); increasing gasoline selectivity (See U.S. Pat. No. 4,970,183); and increasing steam stability (see U.S. Pat. Nos. 4,765,884 and 4,873,211).
In U.S. Pat. No. 3,758,403, use of large-pore cracking catalyst with large amounts of ZSM-5 additive gives only modest increase in light olefin production. A 100% increase in ZSM-5 content (from 5 wt. % ZSM-5 to 10 wt. % ZSM-5) increased the propylene yield less than 20%, and decreased slightly the potential gasoline yield (C5+ gasoline plus alkylate).
When attempting to improve or enhance the catalytic activity of these compositions, the amounts of the various components in a catalyst or catalyst additive and the relevant effect these components have on attrition have to be taken into account in order to maximize attrition resistance. The importance of attrition becomes increasingly acute when, for example, the ZSM-5 content of a catalyst is increased to enhance the catalyst's activity. In certain instances, increasing a catalyst's ZSM-5 content results in the use of less binder and matrix, and as a result, “softer” or more attrition prone particles can be created. Even though particles having a ZSM-5 content up to 60% and an attrition index less than 20 have been reported (U.S. Pat. No. 5,366,948), it has been difficult to prepare catalysts and additives which contain a great majority, i.e., greater than 60% of the active component over the other components in the catalyst. For example, it would be desirable to increase the amount of ZSM-5 to these high levels in certain catalysts in order to produce a particle which is more active in producing C3-C5 olefin.
In U.S. Pat. No. 5,481,057, inventors Bell et al. (Mobil Oil Corporation), disclosed the use of removed (e.g. spent) equilibrium cracking catalyst (E-Cat) from an FCC unit as an alkylating catalyst for upgrading olefins. To achieve these seemingly incompatible objectives, the inventors used a phosphorus stabilized or modified large pore zeolite cracking catalyst, and an unexpectedly effective water activation treatment. This patent is incorporated herein by reference.
Other phosphorus stabilized, shape selective zeolites are also well known and widely used in the art. In U.S. Pat. No. 3,962,364, Young teaches alkylation in the presence of phosphorus-modified zeolite ZSM-5. U.S. Pat. No. 3,965,208, Butter et al, teaches methylation of toluene using ZSM-5 modified by the addition of phosphorus, arsenic or antimony. U.S. Pat. No. 3,972,832 Butter and Kaeding claims a shape selective zeolite with at least 0.78 wt % phosphorus in the crystal structure, while U.S. Pat. No. 4,044,065 claims conversion using this phosphorus-containing zeolite. In U.S. Pat. No. 4,356,338, Young discloses extending catalyst life by treating a shape selective zeolite with phosphorus and/or steam. Together; these patents illustrate the use and benefit of phosphorus treatment/stabilization methods on shape selective zeolites, such as ZSM-5. Each of these patents is incorporated herein by reference.
Phosphorus stabilized large pore cracking catalyst is also known. Pine et al, U.S. Pat. No. 4,454,241, incorporated by reference, discloses a clay derived Y zeolite activated with dihydrogen phosphate or dihydrogen phosphite anion having increased cracking activity.
Although phosphorus treatment of zeolites is widely known, the fragility of the phosphorus/zeolite bond has also been reported. Molecules of phosphoric acid which have interacted with the strong acid sites on the zeolite “can easily be removed by extraction”.
All known commercial FCC processes using phosphorus-stabilized zeolite are believed to operate either water free, or at high temperatures. FCC catalyst is steamed during the stripping step, but steaming occurs at temperatures of 900.degree. to 1000.degree. F. (near the riser top temperature) so that catalysts are not exposed to liquid water. The FCC regenerator typically contains 5-10 psi steam partial pressure (from water of combustion and entrained/or stripping steam), but operates at 1200.degree.-1400.degree. F.
Disclosures such as these show the robustness, stability and versatility of zeolite materials in FCC and related applications. They further provide general guidelines for the use of FCC catalysts in conjunction with the present inventions.
In U.S. Pat. No. 6,916,757, inventor Ziebarth et al. (W.R Grace & Co.) discloses one of many recent advances in developing attrition resistant cracking catalysts and enhancing production of not only C3-C5 olefins, but C2 (ethylene) as well. Other catalysts ha been found to increase the C3-C5 olefins at the expense of ethylene. In the '757 patent (incorporated in its entirety herein by reference for all purposes), the inventors found that they could develop attrition resistant catalyst particles having a high level (30-85%) of stabilized zeolites and having a constraint index of 1 to 12. The stabilized zeolite is bound by a phosphorous compound, alumina and optional binders wherein the alumina added to make the catalyst is about 10% by weight or less and the molar ratio of phosphorous (P2O5) to total alumina is sufficient to obtain an attrition index of about 20 or less.
Particulated catalyst additives can also perform as conventional large pore cracking catalysts for FCC processes and methods such as those disclosed elsewhere herein. These additives are very useful in octane numbers of thea fuel or hydrocarbon product. Such additives also are especially suitable for enhancing yields of C3-C5 olefins. Those olefins are useful in making ethers and alkylates that may be used as octane enhancers for gasoline, as well as useful in making other chemical products. These particulated catalysts and additives are prepared from a number of compounds in addition to the primary active catalytic species. For example, the catalyst compositions can comprise clay and other inorganic oxides in addition to catalytically active ZSM-5. Alumina as an inorganic oxide (e.g. Al2O3) may also be added to (or used as a) catalyst. EP 256 875 reports that alumina in conjunction with rare earth compounds improves hydrothermal stability and selectivity of zeolite Y. The catalyst materials disclosed in the '757 may be used to advantage in the present invention using methods provided elsewhere in the document.
Refiners, e.g., FCC refiners, DCC (Deep Catalytic Cracking) refiners, as well as fixed fluidized bed refiners, would also find it advantageous to enhance ethylene yields in order to maximize the yield of valuable products from their refinery operations. Additives or compositions comprising novel catalysts are potential avenues for enhancing ethylene yields. Using those additives or compositions, however, without materially affecting the yield of other olefins can be difficult, especially in light of the other concerns mentioned above with respect to attrition.
Therefore, with certain refiners, it would not only be highly desirable to prepare a catalyst composition having a high attrition resistance, it would also be desirable to provide catalyst compositions having improved activity for ethylene production as well as substantially maintain the compositions' ability to produce other olefins. Those skilled in the art will also appreciate that improved attrition resistance as well as improved activity will translate into reduced catalyst makeup rates. The catalyst materials, methods and references cited in this Brief Description describe numerous, zeolite-based catalyst formulations. These are given as examples of materials that are useful in the catalytic pocess examples cited later in this disclosure.
The methods of the present invention describe the advantageous use of pyrolytic cracking processes in conjunction with one or more in situ retorting and/or more mobilization processes.
As outlined above, there has been a significant amount of effort to develop methods and systems to economically produce hydrocarbons, hydrogen, and/or other products from oil shale formations. At present, however, there are still many oil shale formations from which hydrocarbons, hydrogen, and/or other products cannot be economically produced. Thus, there is still a need for improved methods and systems for production of hydrocarbons, hydrogen, and/or other products from various oil shale formations.